Low molecular mass organic gelator viscosifiers

ABSTRACT

Compositions and methods of using such compositions to treat subterranean formations are provided. In one embodiment, the methods include providing a drilling fluid including an aqueous base fluid and a low molecular mass organic gelator; and using the drilling fluid to drill at least a portion of a wellbore that penetrates at least a portion of a subterranean formation. In certain embodiments, the methods include providing a drilling fluid including an aqueous base fluid and a low molecular mass organic gelator; and using the drilling fluid to drill at least a portion of a wellbore that penetrates at least a portion of a subterranean formation.

BACKGROUND

The present disclosure relates to systems and methods for drillingand/or treating subterranean formations. Treatment fluids can be used ina variety of subterranean treatment operations. As used herein, theterms “treat,” “treatment,” “treating,” and grammatical equivalentsthereof refer to any subterranean operation that uses a fluid inconjunction with achieving a desired function and/or for a desiredpurpose. Use of these terms does not imply any particular action by thetreatment fluid. Illustrative treatment operations can include, forexample, fracturing operations, gravel packing operations, acidizingoperations, scale dissolution and removal, consolidation operations, andthe like. For example, a fluid may be used to drill a wellbore in asubterranean formation or to complete a wellbore in a subterraneanformation, as well as numerous other purposes. A drilling fluid, or“mud” which a drilling fluid is also often called, is a treatment fluidthat is circulated in a wellbore as the wellbore is being drilled tofacilitate the drilling operation. The various functions of a drillingfluid include removing drill cuttings from the wellbore, cooling andlubricating the drill bit, aiding in support of the drill pipe and drillbit, and providing a hydrostatic head to maintain the integrity of thewellbore walls and prevent well blowouts.

Treatment fluids often contain additives to impart desired physicaland/or chemical characteristics to the fluid, such as viscosifiers.Certain conventional viscosifiers may be difficult to completely removeand may cause damage to the subterranean formation.

BRIEF DESCRIPTION OF THE DRAWINGS

These drawings illustrate certain aspects of some of the embodiments ofthe present disclosure and should not be used to limit or define theclaims.

FIG. 1 is a diagram illustrating the chemical structures of aminoacid-based low molecular mass organic gelators in accordance withcertain embodiments of the present disclosure.

FIG. 2 is a diagram illustrating the chemical structures of a dipeptidelow molecular mass organic gelator in accordance with certainembodiments of the present disclosure.

FIG. 3 is a diagram illustrating the chemical structures of lowmolecular mass organic gelators including fluorenylmethoxycarbonyl andaromatic groups in accordance with certain embodiments of the presentdisclosure.

FIG. 4 is a diagram illustrating the chemical structures of lowmolecular mass organic gelators including urea in accordance withcertain embodiments of the present disclosure.

FIG. 5 is a diagram illustrating the chemical structures of lowmolecular mass organic gelators including pyridine in accordance withcertain embodiments of the present disclosure.

FIG. 6 is a diagram illustrating the chemical structures of lowmolecular mass organic gelators having C₃ rotational symmetry inaccordance with certain embodiments of the present disclosure.

FIG. 7 is a diagram illustrating the chemical structures of lowmolecular mass organic gelators in accordance with certain embodimentsof the present disclosure.

FIG. 8 is a diagram illustrating an example of a wellbore drillingassembly that may be used in accordance with certain embodiments of thepresent disclosure.

While embodiments of this disclosure have been depicted, suchembodiments do not imply a limitation on the disclosure, and no suchlimitation should be inferred. The subject matter disclosed is capableof considerable modification, alteration, and equivalents in form andfunction, as will occur to those skilled in the pertinent art and havingthe benefit of this disclosure. The depicted and described embodimentsof this disclosure are examples only, and not exhaustive of the scope ofthe disclosure.

DESCRIPTION OF CERTAIN EMBODIMENTS

Illustrative embodiments of the present disclosure are described indetail herein. In the interest of clarity, not all features of an actualimplementation may be described in this specification. It will of coursebe appreciated that in the development of any such actual embodiment,numerous implementation specific decisions may be made to achieve thespecific implementation goals, which may vary from one implementation toanother. Moreover, it will be appreciated that such a development effortmight be complex and time-consuming, but would nevertheless be a routineundertaking for those of ordinary skill in the art having the benefit ofthe present disclosure.

The present disclosure relates to compositions and methods for treatingsubterranean formations. More particularly, the present disclosurerelates to treatment fluids including low molecular mass organic gelatorviscosifiers, and methods for using the treatment fluids to treatsubterranean formations.

The present disclosure provides a method that includes providing atreatment fluid including an aqueous base fluid and a low molecular massorganic gelator; allowing the molecular mass organic gelator toviscosify the treatment fluid; and introducing the viscosified treatmentfluid into a wellbore penetrating at least a portion of a subterraneanformation. In certain embodiments, the present disclosure providesmethods including providing a drilling fluid including an aqueous basefluid and a low molecular mass organic gelator; allowing the molecularmass organic gelator to viscosify the drilling fluid; and using thedrilling fluid to drill at least a portion of a wellbore that penetratesat least a portion of a subterranean formation. In some embodiments, thepresent disclosure provides compositions including an aqueous basefluid; a low molecular mass organic gelator; and one or more salts, thecomposition having a density of from about 9 ppg to about 20 ppg.

In some embodiments, the viscosifiers of the present disclosure maycontrol and/or change the viscosity of treatment fluids. For example, incertain embodiments, a viscosifier may reduce or prevent undesirablechanges in viscosity due to temperature variation during the treatmentfluid's transit from the well surface to the bottom of the wellbore andback. In some embodiments, maintaining sufficient viscosity in treatmentfluids is important for a number of reasons, including, but not limitedto, particulate transport, wellbore stability, control and/or reductionof fluid loss into the subterranean formation, and/or diversion of theflow of fluids present within the subterranean formation to otherportions of the formation.

Among the many potential advantages to the methods and compositions ofthe present disclosure, only some of which are alluded to herein, themethods and compositions of the present disclosure may cause lessformation damage than conventional viscosifiers. For example, in certainembodiments, removal of conventional viscosifiers (e.g., clays orpolymeric viscosifiers) may require breaking down covalent bonds with anenzyme or oxidizer, which may not completely oxidize or break up thestabilizers, leaving some viscosified fluid in the formation and causingformation damage. In certain embodiments, the viscosifiers of thepresent disclosure may form a reversibly viscosified fluid that may bealmost completely broken and removed.

In certain embodiments, the viscosifier of the present disclosure mayinclude one or more low molecular mass organic gelators. In someembodiments, low molecular mass organic gelators may includewater-soluble organic molecules. In some embodiments, the low molecularmass organic gelator may have an average molecular weight of about100,000 g/mol or less, of about 10,000 g/mol or less, or of about 1,000g/mol or less. In certain embodiments, the molecular weight of the lowmolecular mass organic gelator may be in the range of from about 100g/mol to about 100,000 g/mol, from about 100 g/mol to about 10,000g/mol, from about 10 g/mol to about 1,000 g/mol, from about 250 g/mol toabout 5,000 g/mol, or from about 5,000 g/mol to about 10,000 g/mol.

In some embodiments, and without wishing to be limited by theory, a lowmolecular mass organic gelator may viscosify a water-based fluidprimarily through hydrogen bonding and supramolecular interactions(e.g., hydrophobic interactions, pi-pi stacking, Van der Waals forces)and generally not through covalent bonding. In some embodiments, the lowmolecular mass organic gelators and/or treatment fluids of the presentdisclosure may not include or act as a surfactant. In some embodiments,the treatment fluids of the present disclosure may be substantiallyand/or entirely free of any surfactants. In certain embodiments, the lowmolecular mass organic gelator may not significantly impact surfacetension characteristics of the treatment fluid and/or surfaces in aformation. For example, in certain embodiments, a low molecular massorganic gelator may not significantly reduce surface tension. In someembodiments, a low molecular mass organic gelator may not reduce surfacetension below 30 mN/m, below 40 mN/m, or below 50 mN/m. In certainembodiments, the low molecular mass organic gelator may not include aviscoelastic compound (e.g., a viscoelastic surfactant).

Examples of low molecular mass organic gelators suitable for certainembodiments of the present disclosure include, but are not limited toamino acid-based compounds, urea compounds, pyridine compounds,cyclohexane-based compounds, and any combination thereof. In someembodiments, a low molecular mass organic gelator many include compoundshaving C₃ rotational symmetry (e.g., the compound does not change after120° rotation about at least one axis).

In certain embodiments, the low molecular mass organic gelator mayinclude one or more amino acid-based moieties (e.g., hydrophobicamino-acid moieties). In some embodiments, a low molecular mass organicgelator may include an amino acid derivative. In some embodiments, anamino-acid based compound may include peptides (e.g., dipeptides).Examples of amino acid moieties suitable for certain embodiments of thepresent disclosure include, but are not limited to phenylalanine,methionine, and the like, and any combination thereof. For example, FIG.1 shows example low molecular mass organic gelators 1001-1006 suitablefor certain embodiments of the present disclosure, including acidicamino acid conjugates of triamide cyclohexane (1001, 1002), neutralamino acid conjugates of triamide cyclohexane (1003, 1004), and basicamino acid conjugates of triamide cyclohexane (1005, 1006), where idemmeans that all three side chains are identical for that compound. FIG. 1also shows a low molecular mass organic gelator based on amino acid andoxalic acid 1007, where R may be a phenyl or isopropyl moiety. Examplesof amino acid-based compounds suitable for certain embodiments of thepresent disclosure include, but are not limited to2,2′-(oxalylbis(azanediyl))bis(2-phenylacetic acid) (compound 1007 whereR is a phenyl moiety) and2,2′-(oxalylbis(azanediyl))bis(3-methylbutanoic acid) (compound 1007where R is an isopropyl moiety).

In some embodiments, a low molecular mass organic gelator may include adipeptide including an α,β-dehydrophenylalanine residue or a derivativethereof. FIG. 2 shows the molecular structure of an example of a lowmolecular mass organic gelator including a dipeptide that includes anα,β-dehydrophenylalanine residue. In some embodiments, an aminoacid-based low molecular mass organic gelator may include one or morefluorenylmethoxycarbonyl (Fmoc) groups. In some embodiments, a lowmolecular mass organic gelator may include one or more aromatic moieties(e.g., phenyl, benzyl, napthyl, napthenyl). FIG. 3 shows the molecularstructure of examples of low molecular mass organic gelators 3001-3008including Fmoc groups (3001-3006) and aromatic groups (3007, 3008).Examples of low molecular mass organic gelators including aromaticmoieties suitable for certain embodiments of the present disclosureinclude, but are not limited to (((9H-fluoren-9-yl)methoxy)carbonyl)phenylalanine (compound 3001),(((9H-fluoren-9-yl)methoxy)carbonyl)glutamic acid (compound 3002),N⁶-(((9H-fluoren-9-yl)methoxy)carbonyl)lysine (compound 3003),(((9H-fluoren-9-yl)methoxy)carbonyl)lysine (compound 3004),(((9H-fluoren-9-yl)methoxy)carbonyl)phenylalanylphenylalanine (compound3005), (((9H-fluoren-9-yl)methoxy)carbonyl)alanylalanine (compound3006), 3,3′-disulfanediylbis(2-benzamidopropanoic acid) (compound 3007),andS-((2-(2-naphthamido)-3-amino-3-oxopropyl)thio)-N-(2-naphthoyl)cysteine(compound 3008).

In certain embodiments, the low molecular mass organic gelator mayinclude urea. FIG. 4 shows example low molecular mass organic gelators4001, 4002 that include urea. Compound 4002 has a central alkyl chainwhere n is between 2 and 8. Examples of low molecular mass organicgelators including urea suitable for certain embodiments of the presentdisclosure include, but are not limited to 1,3-di(pyridin-4-yl)urea(compound 4001), 1,1′-(ethane-1,2-diyl)bis(3-(1-phenylethyl)urea)(compound 4002 where n is 2),1,1′-(propane-1,3-diyl)bis(3-(1-phenylethyl)urea) (compound 4002 where nis 3), 1,1′-(butane-1,4-diyl)bis(3-(1-phenylethyl)urea) (compound 4002where n is 4), 1,1′-(pentane-1,5-diyl)bis(3-(1-phenylethyl)urea)(compound 4002 where n is 5),1,1′-(hexane-1,6-diyl)bis(3-(1-phenylethyl)urea) (compound 4002 where nis 6), 1,1′-(heptane-1,7-diyl)bis(3-(1-phenylethyl)urea) (compound 4002where n is 7), and 1,1′-(octane-1,8-diyl)bis(3-(1-phenylethyl)urea)(compound 4002 where n is 8). In certain embodiments, the low molecularmass organic gelator may include pyridine. FIG. 5 shows example lowmolecular mass organic gelators 5001-5003 that include pyridine.Examples of low molecular mass organic gelators including pyridinesuitable for certain embodiments of the present disclosure include, butare not limited to 5-((3-hydroxypyridin-2-yl)amino)-5-oxopentanoic acid(compound 5001), 2,3-dihydroxy-N¹,N⁴-di(pyridin-3-yl)succinimide(compound 5002), and5,5′-(pyridine-2,6-diylbis(azanediyl))bis(5-oxopentanoic acid) (compound5003).

In some embodiments, a low molecular mass organic gelator many includecompounds having C₃ rotational symmetry (e.g., the compound does notchange after 120° rotation about an axis). FIG. 6 shows example lowmolecular mass organic gelators 6001-6003 that have C₃ rotationalsymmetry. FIG. 6 also shows example R groups 6001a-f for compound 6001.Compounds 1001-1006 of FIG. 1 are also examples of low molecular massorganic gelators having C₃ rotational symmetry. Examples of lowmolecular mass organic gelators having C₃ rotational symmetry suitablefor certain embodiments of the present disclosure include, but are notlimited to N¹,N³,N⁵-tri(pyridin-3-yl)benzene-1,3,5-tricarboxamide(compound 6001 with R groups 6001a),N¹,N³,N⁵-tri(pyridin-4-yl)benzene-1,3,5-tricarboxamide (compound 6001with R groups 6001b),N¹,N³,N⁵-tris(pyridin-3-ylmethyl)benzene-1,3,5-tricarboxamide (compound6001 with R groups 6001c),4,4′,4″-((benzene-1,3,5-tricarbonyl)tris(azanediyl))tribenzoic acid(compound 6001 with R groups 6001d),4,4′,4″-((benzene-1,3,5-tricarbonyl)tris(azanediyl))tris(3-hydroxybenzoicacid) (compound 6001 with R groups 6001e),6,6′,6″-((benzene-1,3,5-tricarbonyl)tris(azanediyl))tris(2-naphthoicacid) (compound 6001 with R groups 6001f, andtris(2-(2-hydroxyethoxy)ethyl)2,2′,2″-((cyclohexane-1,3,5-tricarbonyl)tris(azanediyl))tris(3-phenylpropanoate)(compound 6002).

In certain embodiments, examples of low molecular mass organic gelatorsinclude, but are not limited to a cyclohexane amino acid conjugate, abolaform amino acid derivative, a 1,3,5-triamide cis,cis-cyclohexane, aderivative of the foregoing, or any combination thereof. FIG. 7 depictsmolecular structures of dexamethasone phosphate 7001, betamethasonephosphate 7002, and hydrocortisone phosphate 7003. In some embodiments,the viscosifier may include one or more salts. Examples of saltssuitable for certain embodiments of the present disclosure include, butare not limited to alkali metal salts, alkaline earth metal salts,ammonium salts, transition metal salts, and any combination thereof. Incertain embodiments, the viscosifier may include a salt including Mg²⁺,Ca²⁺, Ba²⁺, and any combination thereof.

In some embodiments, one or more properties of a low molecular massorganic gelator may be tuned by the inclusion or omission of moieties orfunctional groups. Examples of tunable properties of low molecular massorganic gelator viscosifier according to certain embodiments of thepresent disclosure include, but are not limited to sensitivity to pH,sensitivity to temperature, sensitivity to ion presence, and the like.For example, in some embodiments, a low molecular mass organic gelatorwith certain functional groups may be selected in order to cause atreatment fluid including that gelator to viscosify or gel at aparticular pH or temperature, or in the presence of certain conditions(e.g., ionic conditions). In some embodiments, a low molecular massorganic gelator may be tuned by changing the number of hydrophobicsubstituents, changing the number of hydrogen-bonding moieties, addingor removing pH-sensitive moieties, adding or removingtemperature-sensitive moieties, and any combination thereof. In someembodiments, a low molecular mass organic gelator may not viscosify orform a gel in a treatment fluid in ambient or wellbore circulationconditions, but may viscosify or form a gel (e.g., a hydrogel) inresponse to one or more conditions in a subterranean formation. Forexample, in certain embodiments, the low molecular mass organic gelatormay viscosify and/or form a gel in the wellbore and/or subterraneanformation in response to increased temperature in the subterraneanformation as compared to the surface or wellbore, reduced pH in thewellbore and/or subterranean formation, the presence or increasedconcentration of one or more ions in the subterranean formation ascompared to the treatment fluid, and any combination thereof.

As used herein, the term “set” refers to the process of a liquidmaterial transitioning to a more viscous, harder, or more solid materialby curing. For example, in certain embodiments, a fluid may beconsidered “set” when the shear storage modulus is greater than theshear loss modulus of the fluid. In certain embodiments, a fluid may beconsidered “set” or at least partially set when it forms a gel. In someembodiments, the methods of the present disclose may include introducingat least a portion of the treatment fluids into at least a portion of asubterranean formation and causing or allowing the treatment fluid to atleast partially set (e.g., form a solid, semi-solid, gel, plug, etc.).In some embodiments, at least a portion of the low molecular massorganic gelator may form a hydrogel in the wellbore or subterraneanformation. In some embodiments, the viscosification and/or gelation ofthe low molecular mass organic gelator may not include crosslinking. Insome embodiments, the viscosifier and/or treatment fluid may include nomore than 0.1% by weight of any crosslinkable compound that crosslinksin the treatment fluid at ambient and/or downhole conditions.

In some embodiments, a low molecular mass organic gelator of the presentdisclosure may form a reversible gel or reversibly viscosified fluidthat may be almost completely broken and removed from a subterraneanformation. As used herein, in the context of viscosity increase providedby a use of low molecular mass organic gelator, the term “break” or“broken” as used herein refers to a reduction in the viscosity of afluid or gel. In some embodiments, the gel or viscosified fluid formedby the low molecular mass organic gelator may be broken by a change inpH, a change in temperature, the passage of time, the presence ofhydrocarbons (e.g., caused by production of the well), the introductionof a breaker additive, and any combination thereof. Examples of breakeradditives suitable for certain embodiments of the present disclosureinclude, but are not limited to acids, bases, oxidizers, enzymes,chelating agents (e.g., EDTA), or any combination thereof. The acids,oxidizers, or enzymes may be in the form of delayed-release orencapsulated breakers. In some embodiments, a breaker additive may beintroduced into the wellbore in a second treatment fluid and broughtinto contact with the fluid viscosified or gelled by the low molecularmass organic gelator.

In certain embodiments, the viscosifier and/or a treatment fluid may bethixotropic. As used herein, a “thixotropic” material refers to amaterial for which viscosity decreases over time when using a constantor increasing shear rate. As shear rate decreases, the materialgradually recovers the original internal structure. Shear rate may beincreased, for example, by pumping the treatment fluid. In certainembodiments, the low molecular mass organic gelator may impart athixotropic or a substantially thixotropic behavior to a treatmentfluid. In some embodiments, a low molecular mass organic gelator may bepresent in a sufficient amount to make the treatment fluid thixotropic.

When used, the viscosifier may be included in the treatment fluid in anysuitable amount depending on, among other factors, the amount and/ormolecular weight of the viscosifier and the like. In certainembodiments, the viscosifier may be included in the treatment fluid inamount that is from about 0.01% to about 10%, from about 0.1% to about8%, or from about 1% to about 5%, all by weight of the viscosifier inthe treatment fluid. A person of skill in the art with the benefit ofthis disclosure will recognize suitable amounts of the viscosifier toinclude in a treatment fluid of the present disclosure based on, amongother things, desired viscosity of the treatment fluid, other componentsof the treatment fluid (e.g., brines), the and other parameters of theoperation in which the treatment fluid will be used.

In some embodiments, the viscosifier and/or treatment fluids of thepresent disclosure are substantially or entirely free of (e.g., do notinclude) any silicate or aluminate, or includes less than 0.1% by weightof any silicate or aluminate by weight of the viscosifier or treatmentfluid. In some embodiments, the viscosifier and/or treatment fluids ofthe present disclosure are substantially or entirely free of (e.g., donot include) any precipitating compound, or include less than 0.1% byweight of a precipitating compound.

The treatment fluids (e.g., drilling fluids) used in the methods andsystems of the present disclosure may include any aqueous base fluidknown in the art. The term “base fluid” refers to the major component ofthe fluid (as opposed to components dissolved and/or suspended therein),and does not indicate any particular condition or property of thatfluids such as its mass, amount, pH, etc. Aqueous fluids that may besuitable for use in the methods and compositions of the presentdisclosure may include water from any source. Such aqueous fluids mayinclude fresh water, salt water (e.g., water containing one or moresalts dissolved therein), brine (e.g., saturated salt water), seawater,or any combination thereof. In most embodiments of the presentdisclosure, the aqueous fluids include one or more ionic species, suchas those formed by salts dissolved in water. For example, seawaterand/or produced water may include a variety of divalent cationic speciesdissolved therein. In certain embodiments, the density of the aqueousfluid can be adjusted, among other purposes, to provide additionalparticulate transport and suspension in the compositions of the presentdisclosure.

In some examples, an aqueous base fluid may include a monovalent brineor a divalent brine. Examples of monovalent brines suitable for certainembodiments of the present disclosure include, but are not limited tosodium chloride brines, sodium bromide brines, potassium chloridebrines, potassium bromide brines, and the like, and any combinationthereof. Examples of divalent brines suitable for certain embodiments ofthe present disclosure include, but are not limited to magnesiumchloride brines, calcium chloride brines, calcium bromide brines, andthe like. In certain embodiments, salts suitable for the one or moresalts in the treatment fluids may include, but are not limited to analkali metal halide salt, an alkaline earth metal halide salt, and anycombination thereof. Examples of salts suitable for certain embodimentsof the present disclosure include, but are not limited to, sodiumchloride, potassium chloride, potassium formate, potassium carbonate,calcium chloride, calcium bromide, cesium formate, and zinc bromide. Incertain embodiments, a mixture of suitable salts may be used.

In some embodiments, the one or more salts may be present in an amountin a range of from about 15 weight percent (wt %) to about 45 wt % byweight of the treatment fluid. In certain embodiments, the one or moresalts may be present in a range of from about 2 wt % to about 60 wt % byweight of the treatment fluid. In some embodiments, the one or moresalts may be present in an amount in a range of from about 10 wt % orhigher, 40 wt % or higher, or 55 wt % or higher, all by weight of thetreatment fluid.

In some examples, an aqueous base fluid may be a high density brine. Asused herein, the term “high density brine” refers to a brine that has adensity of from about 9 pounds per gallon (ppg) to about 20 ppg orgreater. In some embodiments, a treatment fluid of the presentdisclosure may have a density in the range of from about 9.5 ppg toabout 12 ppg. In certain embodiments, a treatment fluid of the presentdisclosure may have a density in a range of from about 8.5 ppg to about14.5 ppg. In some embodiments, a treatment fluid of the presentdisclosure may have a density in a range of from about 9 ppg or higher,12 ppg or higher, or 14 ppg or higher. One of ordinary skill in the artwith the benefit of this disclosure will recognize where it is desirableto use a dense brine rather than, among other things, a solid weightingagent.

In certain embodiments, the pH of the aqueous fluid may be adjusted(e.g., by a buffer or other pH adjusting agent) to a specific level,which may depend on, among other factors, the types of additivesincluded in the fluid. One of ordinary skill in the art, with thebenefit of this disclosure, will recognize when such density and/or pHadjustments are appropriate. In certain embodiments, the treatmentfluids may include a mixture of one or more aqueous fluids with otherfluids and/or gases, including but not limited to emulsions, foams, andthe like.

In such embodiments, the low molecular mass organic gelator may be atleast partially broken, dissolved, removed, degraded, and the like afterthe low molecular mass organic gelator has been used in a desiredapplication in the subterranean formation in order to at least partiallyreduce or prevent formation damage. In certain embodiments,substantially all of the fluid including a low molecular mass organicgelator may be broken, dissolved, removed, degraded, and the like. Insome embodiments, at least 98% of the fluid including a low molecularmass organic gelator may be broken, dissolved, removed, degraded, andthe like.

In some embodiments, the methods and compositions of the presentdisclosure may provide additives that act, inter alia, as wellborestabilizers. In some embodiments, such additives may be sufficientlysmall or sufficiently of low molecular mass to pass through the pores ofa filter cake and into the shale of a formation and/or small enough topass into the pores of the subterranean formation. In certainembodiments, several different mechanisms may stabilize shale and/orother materials in subterranean formations or wellbores, including butnot limited to inhibition through viscosification or gelation of fluidin the subterranean formation or shale (e.g., pore fluid). In certainembodiments, viscosification or gelation of fluid in the shale mayreduce infiltration of fluid into the shale by lowering effective shalepermeability, resulting in improved wellbore stability. As referencedherein, the phrase “stabilize shale,” “stabilize wellbore,” or variantsthereof, refers to the action of one or more different inhibitionmechanisms, either individually or collectively. As used herein, theterm “stabilizing” and variants thereof do not imply any particulardegree of stabilization, whether partial or otherwise.

In some embodiments, the treatment fluids used in the methods andcompositions of the present disclosure optionally may include any numberof additional additives. Examples of such additional additives include,but are not limited to, surfactants, acids, salts, proppantparticulates, diverting agents, filtration agents, fluid loss controladditives, gas, nitrogen, carbon dioxide, surface modifying agents,tackifying agents, foamers, corrosion inhibitors, scale inhibitors,catalysts, clay control agents, biocides, friction reducers, antifoamagents, bridging agents, flocculants, additional viscosifiers, shaleinhibitors, H₂S scavengers, CO₂ scavengers, oxygen scavengers,lubricants, breakers, weighting agents, relative permeability modifiers,resins, wetting agents, coating enhancement agents, pH control agents,filter cake removal agents, antifreeze agents (e.g., ethylene glycol),and the like. A person skilled in the art, with the benefit of thisdisclosure, will recognize the types of additives that may be includedin the fluids of the present disclosure for a particular application. Insome embodiments, the treatment fluids of the present disclosure may besubstantially or entirely clay-free. For example, in certainembodiments, the treatment fluids of the present disclosure may includeclay in an amount of about 1% or less or about 0.1% or less by weight ofthe treatment fluid. In certain embodiments, the treatment fluids of thepresent disclosure may be substantially free of any polymericviscosifiers. For example, in certain embodiments, the treatment fluidsof the present disclosure may include polymeric viscosifiers in anamount of about 1% or less or about 0.1% or less by weight of thetreatment fluid.

The treatment fluids of the present disclosure may be prepared using anysuitable method and/or equipment (e.g., blenders, mixers, stirrers,etc.) known in the art at any time prior to their use. The treatmentfluids may be prepared at least in part at a well site or at an offsitelocation. In certain embodiments, the viscosifiers and/or othercomponents of the treatment fluid may be metered directly into a basetreatment fluid to form a treatment fluid. In certain embodiments, thebase fluid may be mixed with the viscosifiers and/or other components ofthe treatment fluid at a well site where the operation or treatment isconducted, either by batch mixing or continuous (“on-the-fly”) mixing.The term “on-the-fly” is used herein to include methods of combining twoor more components wherein a flowing stream of one element iscontinuously introduced into a flowing stream of another component sothat the streams are combined and mixed while continuing to flow as asingle stream as part of the on-going treatment. Such mixing can also bedescribed as “real-time” mixing. In other embodiments, the treatmentfluids of the present disclosure may be prepared, either in whole or inpart, at an offsite location and transported to the site where thetreatment or operation is conducted. In introducing a treatment fluid ofthe present disclosure into a portion of a subterranean formation, thecomponents of the treatment fluid may be mixed together at the surfaceand introduced into the formation together, or one or more componentsmay be introduced into the formation at the surface separately fromother components such that the components mix or intermingle in aportion of the formation to form a treatment fluid. In either such case,the treatment fluid is deemed to be introduced into at least a portionof the subterranean formation for purposes of the present disclosure.

The present disclosure in some embodiments provides methods for usingthe treatment fluids to carry out a variety of subterranean treatments,including but not limited to, hydraulic fracturing treatments, acidizingtreatments, and drilling operations. In some embodiments, the treatmentfluid such as a drilling fluid of the present disclosure may beintroduced into at least a portion of a wellbore as it is drilled topenetrate at least a portion of a subterranean formation. The drillingfluid may be circulated in the wellbore during drilling, among otherreasons, to cool and/or lubricate a drill bit and/or drill pipe toprevent them from sticking to the walls of the wellbore, preventblowouts by serving as a hydrostatic head to counteract the suddenentrance into the wellbore of high pressure formation fluids, suspend orremove formation cuttings from the wellbore, and/or enhance thestability of the wellbore during drilling.

The treatment fluids and viscosifiers disclosed herein may directly orindirectly affect one or more components or pieces of equipmentassociated with the preparation, delivery, recapture, recycling, reuse,and/or disposal of the treatment fluids and viscosifiers. For example,and with reference to FIG. 8, the treatment fluids and viscosifiers ofthe present disclosure may directly or indirectly affect one or morecomponents or pieces of equipment associated with an exemplary wellboredrilling assembly 100, according to one or more embodiments. It shouldbe noted that while FIG. 8 generally depicts a land-based drillingassembly, those skilled in the art will readily recognize that theprinciples described herein are equally applicable to subsea drillingoperations that employ floating or sea-based platforms and rigs, withoutdeparting from the scope of the disclosure.

As illustrated, the drilling assembly 100 may include a drillingplatform 102 that supports a derrick 104 having a traveling block 106for raising and lowering a drill string 108. The drill string 108 mayinclude, but is not limited to, drill pipe and coiled tubing, asgenerally known to those skilled in the art. A kelly 110 supports thedrill string 108 as it is lowered through a rotary table 112. A drillbit 114 is attached to the distal end of the drill string 108 and isdriven either by a downhole motor and/or via rotation of the drillstring 108 from the well surface. As the bit 114 rotates, it creates aborehole 116 that penetrates various subterranean formations 118.

A pump 120 (e.g., a mud pump) circulates drilling fluid 122 through afeed pipe 124 and to the kelly 110, which conveys the drilling fluid 122downhole through the interior of the drill string 108 and through one ormore orifices in the drill bit 114. The drilling fluid 122 is thencirculated back to the surface via an annulus 126 defined between thedrill string 108 and the walls of the borehole 116. At the surface, therecirculated or spent drilling fluid 122 exits the annulus 126 and maybe conveyed to one or more fluid processing unit(s) 128 via aninterconnecting flow line 130. After passing through the fluidprocessing unit(s) 128, a “cleaned” drilling fluid 122 is deposited intoa nearby retention pit 132 (i.e., a mud pit). While illustrated as beingarranged at the outlet of the wellbore 116 via the annulus 126, thoseskilled in the art will readily appreciate that the fluid processingunit(s) 128 may be arranged at any other location in the drillingassembly 100 to facilitate its proper function, without departing fromthe scope of the scope of the disclosure.

One or more of the viscosifiers of the present disclosure may be addedto the drilling fluid 122 via a mixing hopper 134 communicably coupledto or otherwise in fluid communication with the retention pit 132. Themixing hopper 134 may include, but is not limited to, mixers and relatedmixing equipment known to those skilled in the art. In otherembodiments, however, the viscosifiers of the present disclosure may beadded to the drilling fluid 122 at any other location in the drillingassembly 100. In at least one embodiment, for example, there could bemore than one retention pit 132, such as multiple retention pits 132 inseries. Moreover, the retention put 132 may be representative of one ormore fluid storage facilities and/or units where the viscosifiers may bestored, reconditioned, and/or regulated until added to the drillingfluid 122.

As mentioned above, the viscosifiers of the present disclosure maydirectly or indirectly affect the components and equipment of thedrilling assembly 100. For example, the disclosed viscosifiers maydirectly or indirectly affect the fluid processing unit(s) 128 which mayinclude, but is not limited to, one or more of a shaker (e.g., shaleshaker), a centrifuge, a hydrocyclone, a separator (including magneticand electrical separators), a desilter, a desander, a separator, afilter (e.g., diatomaceous earth filters), a heat exchanger, any fluidreclamation equipment, and any combination thereof. The fluid processingunit(s) 128 may further include one or more sensors, gauges, pumps,compressors, and the like used store, monitor, regulate, and/orrecondition the viscosifiers.

The viscosifiers may directly or indirectly affect the pump 120, whichrepresentatively includes any conduits, pipelines, trucks, tubulars,and/or pipes used to fluidically convey the treatment fluids downhole,any pumps, compressors, or motors (e.g., topside or downhole) used todrive the treatment fluids into motion, any valves or related jointsused to regulate the pressure or flow rate of the treatment fluids, andany sensors (i.e., pressure, temperature, flow rate, etc.), gauges,and/or combinations thereof, and the like. The treatment fluids andviscosifiers of the present disclosure may also directly or indirectlyaffect the mixing hopper 134 and the retention pit 132 and theirassorted variations.

The treatment fluids and/or viscosifiers of the present disclosure mayalso directly or indirectly affect the various downhole equipment andtools that may come into contact with the treatment fluids andviscosifiers such as, but not limited to, the drill string 108, anyfloats, drill collars, mud motors, downhole motors and/or pumpsassociated with the drill string 108, and any MWD/LWD tools and relatedtelemetry equipment, sensors or distributed sensors associated with thedrill string 108. The treatment fluids and/or viscosifiers of thepresent disclosure may also directly or indirectly affect any downholeheat exchangers, valves and corresponding actuation devices, tool seals,packers and other wellbore isolation devices or components, and the likeassociated with the wellbore 116. The treatment fluids and/orviscosifiers may also directly or indirectly affect the drill bit 114,which may include, but is not limited to, roller cone bits, PDC bits,natural diamond bits, any hole openers, reamers, coring bits, etc.

While not specifically illustrated herein, the treatment fluids and/orviscosifiers of the present disclosure may also directly or indirectlyaffect any transport or delivery equipment used to convey the treatmentfluids and/or viscosifiers to the drilling assembly 100 such as, forexample, any transport vessels, conduits, pipelines, trucks, tubulars,and/or pipes used to fluidically move the treatment fluids and/orviscosifiers from one location to another, any pumps, compressors, ormotors used to drive the treatment fluids and/or viscosifiers intomotion, any valves or related joints used to regulate the pressure orflow rate of the treatment fluids and/or viscosifiers, and any sensors(i.e., pressure and temperature), gauges, and/or combinations thereof,and the like.

An embodiment of the present disclosure is a method that includes:providing a viscosified treatment fluid including an aqueous base fluidand a low molecular mass organic gelator; allowing the molecular massorganic gelator to viscosify the treatment fluid; and introducing theviscosified treatment fluid into a wellbore penetrating at least aportion of a subterranean formation.

In one or more embodiments described in the preceding paragraph, themethod further includes allowing the viscosified treatment fluid tobreak in the wellbore. In one or more embodiments described in thepreceding sentence, the method further includes introducing a breakeradditive into the wellbore and allowing the breaker additive to contactthe viscosified treatment fluid, wherein the viscosified treatment fluidbreaks in response to the contacting. In one or more embodimentsdescribed in the preceding paragraph, the aqueous fluid is a highdensity brine. In one or more embodiments described in the precedingparagraph, the low molecular mass organic gelator is selected from thegroup consisting of: an amino acid-based compound, a urea compound, apyridine compound, a cyclohexane-based compound, and any combinationthereof. In one or more embodiments described in the preceding paragraphthe low molecular mass organic gelator is present in the treatment fluidin an amount of from about 0.1% by weight to about 10% by weight of thetreatment fluid. In one or more embodiments described in the precedingparagraph, the low molecular mass organic gelator includes a compoundhaving a molecular mass of 100,000 g/mol or less. In one or moreembodiments described in the preceding paragraph, the low molecular massorganic gelator includes a compound having a molecular mass of 10,000g/mol or less. In one or more embodiments described in the precedingparagraph, the low molecular mass organic gelator includes a compoundhaving a molecular mass of 1,000 g/mol or less. In one or moreembodiments described in the preceding paragraph, the treatment fluid isintroduced into the wellbore using one or more pumps.

Another embodiment of the present disclosure is a method includingproviding a drilling fluid including an aqueous base fluid and a lowmolecular mass organic gelator; allowing the molecular mass organicgelator to viscosify the drilling fluid; and using the drilling fluid todrill at least a portion of a wellbore that penetrates at least aportion of a subterranean formation.

In one or more embodiments described in the preceding paragraph, thedrilling fluid is substantially clay-free. In one or more embodimentsdescribed in the preceding paragraph, the low molecular mass organicgelator is selected from the group consisting of: an amino acid-basedcompound, a urea compound, a pyridine compound, a cyclohexane-basedcompound, and any combination thereof. In one or more embodimentsdescribed in the preceding paragraph, the low molecular mass organicgelator is present in the drilling fluid in an amount of from about 0.1%by weight to about 10% by weight of the drilling fluid.

Another embodiment of the present disclosure is a composition includingan aqueous base fluid; a low molecular mass organic gelator; and one ormore salts, the composition having a density of from about 9 ppg toabout 20 ppg. In one or more embodiments described in the precedingparagraph, including a bridging agent. In one or more embodimentsdescribed in the preceding paragraph, the composition is substantiallyclay-free. In one or more embodiments described in the precedingparagraph, the low molecular mass organic gelator is selected from thegroup consisting of: an amino acid-based compound, a urea compound, apyridine compound, a cyclohexane-based compound, and any combinationthereof.

In one or more embodiments described in the preceding paragraph, the lowmolecular mass organic gelator is present in the composition in anamount of from about 0.1% by weight to about 10% by weight of thecomposition. In one or more embodiments described in the precedingparagraph, the low molecular mass organic gelator includes a compoundhaving a molecular mass of 100,000 g/mol or less.

Therefore, the present disclosure is well adapted to attain the ends andadvantages mentioned as well as those that are inherent therein. Theparticular embodiments disclosed above are illustrative only, as thepresent disclosure may be modified and practiced in different butequivalent manners apparent to those skilled in the art having thebenefit of the teachings herein. While numerous changes may be made bythose skilled in the art, such changes are encompassed within the spiritof the subject matter defined by the appended claims. Furthermore, nolimitations are intended to the details of construction or design hereinshown, other than as described in the claims below. It is thereforeevident that the particular illustrative embodiments disclosed above maybe altered or modified and all such variations are considered within thescope and spirit of the present disclosure. In particular, every rangeof values (e.g., “from about a to about b,” or, equivalently, “fromapproximately a to b,” or, equivalently, “from approximately a-b”)disclosed herein is to be understood as referring to the power set (theset of all subsets) of the respective range of values. The terms in theclaims have their plain, ordinary meaning unless otherwise explicitlyand clearly defined by the patentee.

What is claimed is:
 1. A method comprising: providing a treatment fluidcomprising an aqueous base fluid and a low molecular mass organicgelator; allowing the molecular mass organic gelator to viscosify thetreatment fluid; and introducing the viscosified treatment fluid into awellbore penetrating at least a portion of a subterranean formation. 2.The method of claim 1, further comprising allowing the viscosifiedtreatment fluid to break in the wellbore.
 3. The method of claim 2,further comprising introducing a breaker additive into the wellbore andallowing the breaker additive to contact the viscosified treatmentfluid, wherein the viscosified treatment fluid breaks in response to thecontacting.
 4. The method of claim 1, wherein the aqueous fluid is abrine having a density of from about 9 ppg to about 20 ppg.
 5. Themethod of claim 1, wherein the low molecular mass organic gelator isselected from the group consisting of: an amino acid-based compound, aurea compound, a pyridine compound, a cyclohexane-based compound, andany combination thereof.
 6. The method of claim 1, wherein the lowmolecular mass organic gelator is present in the treatment fluid in anamount of from about 0.1% by weight to about 10% by weight of thetreatment fluid.
 7. The method of claim 1, wherein the low molecularmass organic gelator comprises a compound having a molecular mass of100,000 g/mol or less.
 8. The method of claim 1, wherein the lowmolecular mass organic gelator comprises a compound having a molecularmass of 10,000 g/mol or less.
 9. The method of claim 1, wherein the lowmolecular mass organic gelator comprises a compound having a molecularmass of 1,000 g/mol or less.
 10. The method of claim 1, wherein thetreatment fluid is introduced into the wellbore using one or more pumps.11. A method comprising: providing a drilling fluid comprising anaqueous base fluid and a low molecular mass organic gelator; allowingthe molecular mass organic gelator to viscosify the drilling fluid; andusing the viscosified drilling fluid to drill at least a portion of awellbore that penetrates at least a portion of a subterranean formation.12. The method of claim 11, wherein the viscosified drilling fluid issubstantially clay-free.
 13. The method of claim 11, wherein the lowmolecular mass organic gelator is selected from the group consisting of:an amino acid-based compound, a urea compound, a pyridine compound, acyclohexane-based compound, and any combination thereof.
 14. The methodof claim 11, wherein the low molecular mass organic gelator is presentin the drilling fluid in an amount of from about 0.1% by weight to about10% by weight of the drilling fluid. 15-20. (canceled)
 21. A methodcomprising: providing a treatment fluid comprising an aqueous basefluid, one or more salts, and a low molecular mass organic gelator, thetreatment fluid having a density of from about 9 ppg to about 20 ppg;allowing the molecular mass organic gelator to viscosify the treatmentfluid; and introducing the viscosified treatment fluid into a wellborepenetrating at least a portion of a subterranean formation.
 22. Themethod of claim 21, further comprising allowing the viscosifiedtreatment fluid to break in the wellbore.
 23. The method of claim 21,further comprising introducing a breaker additive into the wellbore andallowing the breaker additive to contact the viscosified treatmentfluid, wherein the viscosified treatment fluid breaks in response to thecontacting.
 24. The method of claim 21, wherein the low molecular massorganic gelator is selected from the group consisting of: an aminoacid-based compound, a urea compound, a pyridine compound, acyclohexane-based compound, and any combination thereof.
 25. The methodof claim 21, wherein the low molecular mass organic gelator is presentin the treatment fluid in an amount of from about 0.1% by weight toabout 10% by weight of the treatment fluid.
 26. The method of claim 21,wherein the low molecular mass organic gelator comprises a compoundhaving a molecular mass of 100,000 g/mol or less.